In the production of oil from subterranean formations, only a small fraction of the total formation oil can usually be recovered through the use of primary recovery methods. As those skilled in the art recognize, a primary recovery method is one which utilizes only the natural forces present in the reservoir. To recover additional oil, a variety of supplemental production techniques have been developed. In these supplemental techniques, commonly referred to as secondary or tertiary recovery operations, a fluid is introduced into the oil-bearing formation in order to displace oil to a production system comprising one or more production wells. The displacing or "drive" fluid may be an aqueous liquid such as brine or fresh water, a gas such as carbon dioxide, steam or dense-phase carbon dioxide, an oil-miscible liquid such as butane, or an oil and water-miscible liquid such as an alcohol. Often, the most cost-effective and desirable secondary recovery methods involve the injection of steam. In practice, a number of injection and production wells will be used in a given field arranged in conventional patterns such as a line drive, a five spot or inverted five spot, or a seven spot or inverted seven spot.
In the use of the various flooding techniques, it has become a common expedient to add various polymeric thickening agents to the drive fluid to increase its viscosity to a point where it approaches that of the oil to be displaced, thus improving the displacement of oil from the formation. The polymers used for this purpose are often said to be used for "mobility" control.
Another problem encountered is that certain injected drive fluids may be much lighter than the reservoir fluids and thus separate by gravity, rising toward the top of the flowing region and resulting in the bypassing of the lower regions. This phenomena is known as gravity override.
Also encountered in the use of the various flooding techniques is a situation caused by the fact that different regions or strata often have different permeabilities. When this situation is encountered, the drive fluid may preferentially enter regions of higher permeability due to their lower resistance to flow rather than the regions of low permeability where significant volumes of oil often reside.
It therefore is often desirable to plug the regions of high permeability, or "thief" zones, either partly or entirely, so as to divert the drive fluid into regions of lower permeability. The mechanical isolation of these thief zones has been tried but vertical communication among reservoir strata often renders this method ineffective. Physical plugging of the high permeability regions by cements and solid slurries has also been tried with varying degrees of success; however, these techniques have the drawback that still-productive sites may be permanently closed.
As a result of these earlier efforts, the desirability of designing a slug capable of sealing off the most permeable layers so that the drive fluid would be diverted to the underswept, "tighter" regions of the reservoir, became evident. This led to the use of oil/water emulsions, as well as gels and polymers for controlling the permeability of the formations. This process is frequently referred to as "flood conformance" or "profile control", a reference to the control of the vertical permeability profile of the reservoir. Profile control agents which have been proposed include oil/water emulsions and gels, e.g., lignosulfate gels and polymeric gels, with polymeric gels being the most extensively applied in recent years.
Among the polymers so far examined for improving flood conformance are polyacrylamides, polysaccharides, celluloses, furfural-alcohol and acrylic/epoxy resins, silicates and polyisocyanurates. A major part of this work has been conducted with the polyacrylamides, both in their normal, non-crosslinked form, as well as in the form of metal complexes, as described, for example, in U.S. Pat. Nos. 4,009,755, 4,069,869 and 4,413,680. In either form, the beneficial effects derived from these polyacrylamides seem to dissipate rapidly due to shear degradation during injection and sensitivity to reservoir brines, low pH and high temperature. To overcome these problems and to achieve deeper polymer penetration into the reservoir, dilute solutions of these polymers have sometimes been injected first and then complexed in-situ.
Another group of polymeric thickeners which has received considerable attention for use in improving flooding are polysaccharides, particularly those produced by the action of bacteria of the genus Xanthomonas on carbohydrates. For example, U.S. Pat. Nos. 3,757,863 and 3,383,307 disclose a process for mobility control by the use of polysaccharides.
U.S. Pat. Nos. 3,741,307, 4,009,755 and 4,069,869 disclose the use of polysaccharides in the control of reservoir permeability. U.S. Pat. No. 4,413,680 describes the use of crosslinked polysaccharides for selective permeability control in oil reservoirs.
U.S. Pat. No. 3,908,760 describes a polymer waterflooding process in which a gelled, water-soluble Xanthomonas campestris polysaccharide is injected into a stratified reservoir to form a slug, band or front of gel extending vertically across both high permeability and low permeability strata. This patent also suggests the use of complexed polysaccharides to block natural or man-made fractures in formations.
Another type of polysaccharide which has been experimented with in the area of profile control is the non-xanthan, heteropolysaccharide S-130. S-130 is a member of a group of welan gums and is produced by fermentation with a microorganism of the genus Alcaligenes. Another welan gum heteropolysaccharide, known as S-194, is also produced by fermentation with a microorganism of the genus Alcaligenes. A notable characteristic of the heteropolysaccharide S-130 is that it develops a high viscosity in saline waters. This is particularly so in brines which contain divalent cations such as Ca.sup.2+ and Mg.sup.2+ or monovalent cations such as Na.sup.+ and K.sup.+. U.S. Pat. No. 4,658,898 discloses the use of welan gum S-130 in saline waters. Crosslinking with trivalent cations, such as chromium, aluminum, zirconium and iron is also disclosed. Additionally, crosslinking with organic compounds containing at least two positively charged nitrogen atoms is disclosed in U.S. Pat. No. 4,658,898; while Ser. No. 283,399, filed on Dec. 12, 1988, discloses welan gums crosslinked with phenolic resins or mixtures of phenols and aldehydes.
The use of various block copolymers for mobility control in waterflooding operations is described in U.S. Pat. Nos. 4,110,232, 4,120,801 and 4,222,881. Chung et al., U.S. Pat. No. 4,653,585, disclose the use of block copolymers, which may be crosslinked with polyvalent metal ions, for use as permeability control agents in enhanced oil recovery applications.
While a number of the different compositions discussed have been proposed for permeability control, some of these compositions may be unsuitable for use as permeability control agents under certain circumstances. For example, the polymers of Chung et al, may not be effectively crosslinked with polyvalent metal ions under all conditions encountered in the enhanced oil recovery applications, e.g., in acidic conditions commonly found in carbon dioxide (CO.sub.2) flooding operations. Polyacrylamides display instability in the presence of high brine concentration at temperatures over 70.degree. C. Xanthan gums are very brine tolerant but display thermal instability, even at temperatures below 60.degree. C. Still, other polymers are unsuitable as permeability control agents when used in conjunction with steam flooding operations. This is due to the fact that they lose their structural integrity at the high temperatures generated during such operations. In view of the severe conditions which include both high brine concentrations, elevated temperatures or both, so-called hostile environment polymers, such as those marketed by the Phillips Petroleum Company of Bartlesville, Okla. and the Hoechst Celanese Corporation of Somerville, N.J. have been developed.
Basic to the problem of diverting displacing fluid with polymeric gels is the necessity of placing the polymer where it is needed, i.e. selective penetration into the high permeability zone. In general, there are two ways to deliver polymer gels into the formation. The first method is to inject gelled polymer into the formation. This is the so-called surface gelation method. The advantage of this method is that the polymer will enter the loose, more highly permeable zone in preference to the tighter, low permeability zone, due to the high viscosity of the gelled polymer. Another advantage is that gelation is ensured since the gel is prepared at the surface. However, depending upon the characteristics of the polymer selected, it is possible that the polymer gel will not penetrate far enough to block a high pore volume of the designated zone at low pumping pressures and low pumping rates. This is particularly so when a high pressure drop is experienced within a small radius of the injection wellbore. While increasing pumping pressure and/or flow rate could serve to diminish this problem, there are increased risks of fracturing the reservoir and degrading the gel structure by high shear forces, as those skilled in the art will readily understand.
The second method is the so-called in-situ gelation method, in which separate slugs of polymer, one containing an inactive crosslinker (such as dichromate), the other, an activator (reducing agents such as thiourea and bisulfite), are injected sequentially into the reservoir. Gelation occurs when the two parts meet in the reservoir. With this method, shear degradation is reduced and the penetration of polymer is improved because of the lower viscosity of the ungelled polymer. However, because the solution will generally possess a low viscosity, the non-crosslinked polymer slug can also enter the tight zone and cause its blockage, defeating the purpose of the profile control treatment. A further disadvantage of this method is that there is no guarantee that the two slugs of treatment will be placed in the same area and mix well enough to form a strong gel.
There are also many other gel systems that are formed in-situ. One system disclosed in U.S. Pat. No. 3,557,562 contains acrylamide monomer, methylene-bis-acrylamide as an organic crosslinker, and a free radical initiator. This system undergoes polymerization in the formation to give a polyacrylamide crosslinked with methylene-bis-acrylamide. However, the viscosity of the solution when injected is like that of water. Unless mechanical isolation is used, these solutions are quite capable of penetrating low permeability, oil bearing zones. Another form of in-situ gelation involves the injection of polyacrylamide containing chromium in the form of chromate. A reducing agent such as thiourea or sodium thiosulfate is also injected to reduce the chromate in-situ to Cr.sup.+3, a species capable of crosslinking hydrolyzed polyacrylamide. Even though the polyacrylamide solution has a viscosity greater than water, it is not capable of the selectivity of a preformed gel. Thus, polyacrylamides crosslinked with chromium in-situ can also go into low permeability zones. It is not useful to crosslink polyacrylamides above ground and inject them as gels, because polyacrylamide gels undergo shear degradation.
To improve upon the aforementioned polymer delivery methods, several solutions have been proposed. U.S. Pat. No. 4,606,407 discloses a method in which polymers are gelled in a controlled manner through the use of rapid and delayed polyvalent metal gelling agents. The gelling agents disclosed are capable of forming two or more coordinate bonds with donor atoms in the polymers. Polymers disclosed within U.S. Pat. No. 4,606,407 as having the requisite donor atoms for forming coordinate linkages include polyacrylamides, other acrylic polymers and polysaccharides. In the practice of the method of U.S. Pat. No. 4,606,407, a solution or dispersion of the polymer is first lightly gelled on the surface through the use of the rapid polyvalent metal crosslinking agent. The delayed polyvalent metal crosslinking agent is also added to the solution or dispersion so as to effect complete gelation at a later period of time when the desired depth of penetration has been achieved. U.S. Pat. No. 4,606,407 is hereby incorporated by reference in its entirety for all that it discloses.
Another solution was proposed in U.S. Pat. No. 4,901,795, the contents of which are hereby incorporated by reference in their entirety. U.S. Pat. No. 4,901,795 discloses a two stage gel system employing a xanthan-based first stage gel for ex-situ gelation and a second stage gel-forming composition which gels in-situ. Selective placement of this two-stage system is effected through the use of a Cr crosslinked xanthan gel as the first stage system. As is known in the art, xanthan heteropolysaccharides may be crosslinked with metal ions such as Cr.sup.+3 above ground to yield gels. These gels are shear stable and shear thinning and can be injected into the formation where they then reheal. Due to this unique rheological property, such gels selectively enter high permeability zones. However, as is well known, xanthan-Cr gels have poor thermal stability at temperatures greater than about 140.degree. F.
In the practice of the invention of U.S. Pat. No. 4,901,795, a first gel is placed into an aqueous solution in an amount sufficient to enter the pores of a formation's more permeable zones. Such a gel, as mentioned, forms ex-situ and is shear thinning. A second, in-situ-forming gel is combined with the first gel, the second gel substantially more resistant to formation conditions than the first gel. After mixing and permitting the first gel to gel ex-situ, the composition containing ungelled in-situ gel components is directed into the formation's more permeable zones by the selective penetration of the ex-situ gel, where it reheals. Thereafter, heat from the formation causes the in-situ gel to firm-up and form a solid gel which is substantially more resistant to formation conditions than the first gel.
While the two-stage gel system of U.S. Pat. No. 4,901,795 provides a useful solution to the gel selectivity problem, it has a rather limited range of pH values within which first stage gelation can occur. This is due to the fact that the gelation of the majority of xanthan gum heteropolysaccharides, including the heteropolysaccharide of the preferred embodiment of U.S. Pat. No. 4,901,795, is pH limited.
Therefore, what is needed is a method in which a selective ex-situ gel composition capable of gelling over a broad range of pH conditions can be combined with an in-situ gel composition so as to obtain greater selectivity in closing a zone of greater permeability in a formation while forming a gel having substantially better qualities to withstand formation conditions.